Shale Oil Fiasco

[D Coyne + 305]

40 minutes ago, James Gautreau said:

My mistake I'm talking national and you're talking Permian.

James,

As we were discussing resources in the Permian basin, growth in Permian basin output is what I thought you were talking about.

[Gerry Maddoux + 3,627]

Oklahoma's issues were apparent early on. It's so porous up there, and there's so much of a water load, that it wouldn't take a genius to figure out you can't take out all that water and place it in sealed, inescapable disposal wells without repercussions. And the density of disposal wells was something out of a science fiction extravaganza--they dotted the landscape everywhere and finally even the Corporation Commission (Oklahoma's equivalent of the Texas Railroad Commission) had to admit that they were causing increasing seismic activity. As a native Oklahoman, I hate to see it go bust. I grew up all the way across the state with one-tenth the underground water but even there we had a huge sinkhole close to our property back during the big drought. 

I'm not rooting for this to happen but I suspect seismic activity to begin down in the Delaware. Anyone who has been to Carlsbad Caverns recalls the giant underground limestone caverns. Well, they don't abruptly end when you leave that area. The Delaware is fairly porous. The lithographic network has heretofore been held in place by high pressures and voluminous amounts of natural gas exerting equal tangential wall force. That's being changed at a rapid rate. What might save this from happening is their use of inhole water and ng--it's much more environmentally friendly.  

The Greens are right in one aspect of fracking shale: there are unintended consequences. 

[Gerry Maddoux + 3,627]

While on the subject of NG, did you happen to notice what New England's price per btu of Nat Gas peaked at yesterday? Just over $15.

That's what you get when you block pipeline construction. They could have had it for $2.50.

Oh well, their choice.

[James Gautreau + 86]

16 minutes ago, Gerry Maddoux said:

While on the subject of NG, did you happen to notice what New England's price per btu of Nat Gas peaked at yesterday? Just over $15.

That's what you get when you block pipeline construction. They could have had it for $2.50.

Oh well, their choice.

Sea going LNG would be a god send to these people. That's 12.50 profit  per mbtu.

[wrs + 893]

26 minutes ago, James Gautreau said:

Sea going LNG would be a god send to these people. That's 12.50 profit  per mbtu.

But then not only do you still need pipelines, you have to build the decompression facility as well.   LOL, NIMBY!

[James Gautreau + 86]

9 minutes ago, wrs said:

But then not only do you still need pipelines, you have to build the decompression facility as well.   LOL, NIMBY!

All you need is a nat gas fired gas turbine that generates electricity. They use the exhaust heat to warm the lng, thus achieving nearly 100% efficiency.

The cold energy of LNG can be used for cooling the exhaust fluid of the gas turbine which is working in closed joule cycle with Argon gas as fluid. Thus near 100% conversion efficiency to electricity is achieved for the LNG/natural gas consumed by the gas turbine as its exhaust heat is fully used/absorbed for the gasification of LNG.

[James Gautreau + 86]

The problem is that much of the US shale oil economics are opaque. Much investment into shale oil companies in recent years has been based on company estimates of increasing oil reserves. However the numbers are subject to a major conflict of interest. Since 2008 the Securities and Exchange Commission has allowed oil companies to use “proprietary methods” to determine reserves, that are not subject to disclosure. So long as production was booming and money plentiful, nobody minded much. Now that is changing. Recently the CEO of one of the largest companies in the Permian Basin, Scott Sheffield of Pioneer Natural Resources admitted that the oil industry is running out of Tier 1 acreage for shale oil. That is what are called “sweet spots,” where costs are low enough to be profitable. That is a major shift for Sheffield who only two years ago compared the Permian Basin shale reserves to Saudi Arabia.

What is likely at this juncture is further decline in production rates in the US shale oil sector and thus, US oil overall. The shale boom was known to be dependent on wells that reached peak output then depleted far faster than conventional wells. Technology helped mitigate the effects but only so far as money was cheap and oil prices rising. Since 2018 oil prices have fallen. In October 2018 West Texas Intermediate oil sold for over $75 a barrel. Today it is about $56 or dangerously near breakeven for most shale oil companies.

Shin Kim, at S&P Global Platts sees “the potential for shale to disappoint faster than the industry thinks.” She says, “Nothing else out there that can match US shale’s production growth rate of a million or a million and a half barrels of oil a day, and it’s a consistent level of growth.”

The geopolitical consequences of a rapid decline in US shale oil would have serious impact on US foreign policy options and, as US oilfield investment declines, also on the US economy, not good news for a Trump re-election. One ominous sign is the fact that while in earlier shale downturns shale oil frackers parked unused equipment waiting for a revival in demand, this time the equipment is being stripped down for parts or sold for scrap.

F. William Engdahl is strategic risk consultant and lecturer, he holds a degree in politics from Princeton University and is a best-selling author on oil and geopolitics, exclusively for the online magazine “New Eastern Outlook.”

[James Gautreau + 86]

Then there's people like this that will only sell when oil is triple digits, well into triple digits. 

https://www.chron.com/business/energy/article/He-Paid-1-50-an-Acre-for-Barren-Texas-Land-Now-14427388.php

[Gerry Maddoux + 3,627]

12 minutes ago, James Gautreau said:

Now that is changing. Recently the CEO of one of the largest companies in the Permian Basin, Scott Sheffield of Pioneer Natural Resources admitted that the oil industry is running out of Tier 1 acreage for shale oil. That is what are called “sweet spots,” where costs are low enough to be profitable. That is a major shift for Sheffield who only two years ago compared the Permian Basin shale reserves to Saudi Arabia.

Not at all. Though I'm sure his comments are heartfelt, they don't jive with independent assessment. Here's what the big accounting firm Deloitte and Touche said about the Permian, in Mr. Sheffield's backyard: 

Rock quality is important but is not necessarily the main performance differentiator. According to Deloitte’s analysis of all drilled wells in the Eagle Ford and Permian, the ranking of acreage (e.g., “Tier 1, Tier 2, Tier 3”) does not influence well performance to the extent previously assumed. More than 40% of wells drilled outside the core of the western Delaware area reported initial 180-day normalized productivity of more than 1,000 barrels of oil equivalent per day (boed). In the Eagle Ford, a comparable number of high-performing wells exist across acreage tiers.

[Gerry Maddoux + 3,627]

And this:

Bigger is also not always better. The statistical analysis further notes wells drilled over the last two to three years, with complex and intense completion designs (i.e., longer laterals, more proppants, etc.) actually led to diminished productivity, explaining some of the concerns from investors and financial markets. During this period, more than 3,000 wells that were completed with massive volumes of proppant (in excess of 1,800 pounds per foot) yielded productivity below 750 boed per 10,000 feet of perforated interval. Despite an increase in completion intensity of more than 40%, approximately 50% of U.S. horizontal wells had the normalized 180-day productivity of below 750 boed in the past four years.

[Gerry Maddoux + 3,627]

And even this, which is what I've been preaching about tailored completions:

Optimizing well designs can boost capital efficiency. Deloitte found approximately 67% of wells in the Permian have been under- or over-engineered. A more balanced formation-and-engineering equation could improve the capital efficiency of Permian operators by approximately 23%. Similarly, approximately 60% of Eagle Ford wells have been under- or over-engineered. An optimal completion design strategy could increase capital efficiency of Eagle Ford operators by 19%.

(These are the things that are going to keep the shale revolution going: buy cheap, doesn't much matter if it's tier 1,2, or 3 so long as you don't use too much proppant or push your laterals out too far, but what REALLY matters is how you utilize what comes back from the well bit Measurements While Drilling, and how much machine learning you allow to happen, and how good your software is. I may have elaborated this earlier: a well that I had a little interest in was drilled in 39 hours, one trip down hole, vertical and horzontal, curve, shoe to shoe, and that cut the cost by 20%, raised the production by another 20%. It was in Tier-2 property.) 

[James Gautreau + 86]

[James Gautreau + 86]

[Coffeeguyzz + 454]

wrs/James

The article right now on oilpricedotcom describing the high New England natgas price includes the description of the LNG terminal outside Boston Harbor -  the Northeast Gateway Deepwater Port.

It is a dual buoy system to which 2 FSRUs can be tethered (as was done last February with the Exemplar and Express) and the regasification occurs onboard and the gas is directly injected into the short, underwater  pipelines which are connected to the grid.

A world record sendout rate was achieved of 800 million cubic feet/day, although that pace was only briefly sustained during the high demand window of early evening.

This model is being rapidly copied off Bangledesh and several other nations as it is quick and cheap.

Several other nations are setting up/have set up dockside berthage for longer term FSRU employment with re-supply done by Ship to Ship LNG transfer.

[James Gautreau + 86]

12 minutes ago, Coffeeguyzz said:

wrs/James

The article right now on oilpricedotcom describing the high New England natgas price includes the description of the LNG terminal outside Boston Harbor -  the Northeast Gateway Deepwater Port.

It is a dual buoy system to which 2 FSRUs can be tethered (as was done last February with the Exemplar and Express) and the regasification occurs onboard and the gas is directly injected into the short, underwater  pipelines which are connected to the grid.

A world record sendout rate was achieved of 800 million cubic feet/day, although that pace was only briefly sustained during the high demand window of early evening.

This model is being rapidly copied off Bangledesh and several other nations as it is quick and cheap.

Several other nations are setting up/have set up dockside berthage for longer term FSRU employment with re-supply done by Ship to Ship LNG transfer.

Do you know how they do it on ship?

[Coffeeguyzz + 454]

James

I am not aware of the specifics, but Golar, Excelerate and Hoegh are the big players and - I believe- use different methods.

I have read that seawater baths are used in some processes, while high ambient airflow (aka blowers) are used in others.

This entire field of liquefaction and regasification fascinates me as it continues to evolve and various companies are vigorously engaged.

That post by ceo energemeiser the other day contained a wealth of high value introductory data.

[D Coyne + 305]

1 hour ago, Gerry Maddoux said:

And even this, which is what I've been preaching about tailored completions:

Optimizing well designs can boost capital efficiency. Deloitte found approximately 67% of wells in the Permian have been under- or over-engineered. A more balanced formation-and-engineering equation could improve the capital efficiency of Permian operators by approximately 23%. Similarly, approximately 60% of Eagle Ford wells have been under- or over-engineered. An optimal completion design strategy could increase capital efficiency of Eagle Ford operators by 19%.

(These are the things that are going to keep the shale revolution going: buy cheap, doesn't much matter if it's tier 1,2, or 3 so long as you don't use too much proppant or push your laterals out too far, but what REALLY matters is how you utilize what comes back from the well bit Measurements While Drilling, and how much machine learning you allow to happen, and how good your software is. I may have elaborated this earlier: a well that I had a little interest in was drilled in 39 hours, one trip down hole, vertical and horzontal, curve, shoe to shoe, and that cut the cost by 20%, raised the production by another 20%. It was in Tier-2 property.) 

Gerry,

Once all of these improvements are applied, there is very little future progress that will be made.  Also there are some areas that are clearly better than others, you can use shale profile and break out performance by county to see this clearly (and no doubt it is far more granular than this).  Only so many wells can be drilled in a given area without interference, going back to refrack wells may not make economic sense in most cases.  Generally the average well cost has been going up, though perhaps well cost per barrel of EUR (which is the more important metric) has likely fallen over time.  Eventually drilling poorer quality rock will reverse this trend.  This has been the case in every field ever developed, it is highly unlikely this general rule will not be followed in tight oil plays, in my opinion.

[Gerry Maddoux + 3,627]

53 minutes ago, D Coyne said:

Once all of these improvements are applied, there is very little future progress that will be made.  Also there are some areas that are clearly better than others, you can use shale profile and break out performance by county to see this clearly (and no doubt it is far more granular than this).  Only so many wells can be drilled in a given area without interference, going back to refrack wells may not make economic sense in most cases.  Generally the average well cost has been going up, though perhaps well cost per barrel of EUR (which is the more important metric) has likely fallen over time.  Eventually drilling poorer quality rock will reverse this trend.  This has been the case in every field ever developed, it is highly unlikely this general rule will not be followed in tight oil plays, in my opinion.

Agree with your summation. I know a lot more about the Bakken, where I have minerals and overrides in the five major counties. Long before Deloitte analyzed the Permian, the Bakken "tiers"had already undergone extensive reshuffling . . . and it didn't always match either the thickness of the shale, how close it was to the anticline, or other factors. Dunn County was considered mostly Tier-2 and -3, until the giant Lars well was brought in (about 5,400 bll/d IP as I recall) on Tier-3 minerals. Then Marathon moved over just a bit northeast and drilled ten great wells on Tier-2 acreage.

They've refracked about 200 wells up there and have seen an additional 200,000 to 250,000 blls/well, which makes for good economics. They have the converse of the Permian parent-child problem in the Bakken: child wells are dense (about 12/1280 A) and when you frack one it improves the parent (2008-2010 vintage). But those wells in the Bakken in general don't have as splashy an IP, and decline just as rapidly, so there's that. When I bought my property up there, McKenzie was the hot county; Williams wasn't highly regarded. As it happened, I've had more production from Williams county than all the rest put together--despite a much better isopach map for McKenzie. 

I really do believe that LNG is going to push this shale LTO production. Why the LTO fields, rather than the dry gas fields? Because the LTO fields are where Exxon, Occidental, Chevron, BP have bought so much acreage. Too much, in fact, to fold their tents. Vast swaths, as I'm sure you're aware. I believe Oxy is in trouble unless rising tide oil prices lift all boats. CVX and XOM are both going to get into the LNG business in a big way. CVX already has a good chunk of that Barrow's Island facility off Australia (Gorgon?), so they see from both sides what is happening. I suspect they're making money hand over fist from LNG down under. And with the Green Movement coming on hard, with removal of nearly all acidic oxides by the cooling liquifaction process, it's likely going to draw a slight premium to pipeline gas.  

[D Coyne + 305]

16 hours ago, Gerry Maddoux said:

Agree with your summation. I know a lot more about the Bakken, where I have minerals and overrides in the five major counties. Long before Deloitte analyzed the Permian, the Bakken "tiers"had already undergone extensive reshuffling . . . and it didn't always match either the thickness of the shale, how close it was to the anticline, or other factors. Dunn County was considered mostly Tier-2 and -3, until the giant Lars well was brought in (about 5,400 bll/d IP as I recall) on Tier-3 minerals. Then Marathon moved over just a bit northeast and drilled ten great wells on Tier-2 acreage.

They've refracked about 200 wells up there and have seen an additional 200,000 to 250,000 blls/well, which makes for good economics. They have the converse of the Permian parent-child problem in the Bakken: child wells are dense (about 12/1280 A) and when you frack one it improves the parent (2008-2010 vintage). But those wells in the Bakken in general don't have as splashy an IP, and decline just as rapidly, so there's that. When I bought my property up there, McKenzie was the hot county; Williams wasn't highly regarded. As it happened, I've had more production from Williams county than all the rest put together--despite a much better isopach map for McKenzie. 

I really do believe that LNG is going to push this shale LTO production. Why the LTO fields, rather than the dry gas fields? Because the LTO fields are where Exxon, Occidental, Chevron, BP have bought so much acreage. Too much, in fact, to fold their tents. Vast swaths, as I'm sure you're aware. I believe Oxy is in trouble unless rising tide oil prices lift all boats. CVX and XOM are both going to get into the LNG business in a big way. CVX already has a good chunk of that Barrow's Island facility off Australia (Gorgon?), so they see from both sides what is happening. I suspect they're making money hand over fist from LNG down under. And with the Green Movement coming on hard, with removal of nearly all acidic oxides by the cooling liquifaction process, it's likely going to draw a slight premium to pipeline gas.  

Gerry,

There is a spread in the well results in any county so there may be a few high productivity wells here and there, but what matters for the field or any operator is average results.  In investor presentations operators typically pick there best 5% of wells, draw up a well profile for that high productivity group of wells and label them as "typical" results.  Chart below has cumulative average profiles for wells in the ND Bakken/Three Forks that started producing from 2016 to 2019, by county.  The top three counties as far as average cumulative well profile are Dunn, McKenzie, and Mountrail.  Williams has a similar color to Dunn (orange to my eye) but is the lower well profile (about 210 kbo cumulative at 36 months).

Eventually they will run out of room in the "big 4 counties" for new wells.  On refracks, 200 wells is not a lot when we consider that about 14,559 wells had been completed in the ND Bakken/Three Forks through October 2019 (from shale profile, not including "other" formations).  200/14559=1.4%.  Higher oil prices in the future might increase this number, but it is unlikely to rise above 5% (and 5% is a stretch, in my opinion.)

I don't follow LNG, but in general I agree that the natural gas will likely be sold in some manner and that should help profits, as I suggested it is not going to make a huge difference, my model assumes $1.50/MCF with at 25% bump for NGL sales, increasing the assumed wellhead natural gas price to $2.50/MCF (and assuming this is used to offset LOE for the tight oil well) drops the breakeven wellhead oil price by roughly 10%.  Not sure if wellhead natural gas prices will reach $2.50/MCF (again assuming NGL sales bump the equivalent price to about $3.10/MCF) any time soon, my guess is 2025 at the earliest, but that is a WAG.

Edited December 25, 2019 by D Coyne

[James Gautreau + 86]

Well now let's think about that. If the focus in the shale patch becomes the gas and not the oil. What sort of market dynamics would that create? Since the gas can now get to the coast, and in a less expensive manner, that means the price will remain low. And if oil becomes scarce as I predict, there will be more and more wells drilled, and thus more and more gas, which means even lower prices. The oil to gas ratio could surge to a record. Typically 10 to 1, I think the record is 45 to 1. If oil goes to $200 and gas drops to $1, that would mean an oil to gas ratio of 200 to 1. Demand for gas would surge, demand growth might surge to over 1%. After awhile oil price would collapse, the drilling would begin to slow and then and only then would gas price start to move higher. 

[Gerry Maddoux + 3,627]

18 minutes ago, D Coyne said:

I don't follow LNG, but in general I agree that the natural gas will likely be sold in some manner and that should help profits, as I suggested it is not going to make a huge difference, my model assumes $1.50/MCF with at 25% bump for NGL sales, increasing the assumed wellhead natural gas price to $2.50/MCF (and assuming this is used to offset LOE for the tight oil well) drops the breakeven wellhead oil price by roughly 10%.  Not sure if wellhead natural gas prices will reach $2.50/MCF (again assuming NGL sales bump the equivalent price to about $3.10/MCF) any time soon, my guess is 2025 at the earliest, but that is a WAG.

 

13 minutes ago, James Gautreau said:

Well now let's think about that. If the focus in the shale patch becomes the gas and not the oil. What sort of market dynamics would that create? Since the gas can now get to the coast, and in a less expensive manner, that means the price will remain low. And if oil becomes scarce as I predict, there will be more and more wells drilled, and thus more and more gas, which means even lower prices. The oil to gas ratio could surge to a record. Typically 10 to 1, I think the record is 45 to 1. If oil goes to $200 and gas drops to $1, that would mean an oil to gas ratio of 200 to 1. Demand for gas would surge, demand growth might surge to over 1%. After awhile oil price would collapse, the drilling would begin to slow and then and only then would gas price start to move higher. 

With respect to you both, I see this somewhat differently: oil and gas pricing used to move hand in glove (11:1), but that decoupled dramatically, and now, at long last, it's going to recouple. Why? Supply/Demand.

NG: The Marcellus, which now produces nearly 40% of US natural gas, is pretty much going to wither on the vine--nobody can make a profit at these NG prices. It'll take a few months, but not many. Chevron's 10B impairment was about the last gasp. Forty-percent is huge: there's going to be a massive hole in the supply chain at the exact time LNG is surging like nothing else I've ever seen in my long life. 

Oil: LTO from shale is going to decline too, for the same reasons. Especially if Mr. Berman is right, and we're going back down to $52 oil--that will be the fatal blow to an awful lot of companies. With a decline in the shale-drilling frenzy for LTO, there goes another very large volume of by-product NG. 

Unless I'm mistaken, we're setting the stage for a very tight market--about this time next year--in both domestic LTO and NG. Absent those prodigious volumes spewing forth from the thick shale plate (very small in area) of the Marcellus, there is no way for oil prices to shoot upward in the face of $1 NG. Absent these dry gas fields (and I'll admit that the Haynesville has the potential for much more, especially with Jerry Jones at the helm of Comstock production), LTO and NG will once again couple. My prediction is that it won't ever make it back to that cozy 11:1, but maybe 20:1, so at $100 oil, NG would be $5. I respect your modeling, Dennis, but into the mix is thrown a divergence (huge surge in NG from Marcellus). Into the mix is also thrown another divergence: LNG is much more profitable than LTO. I'm saying that when these two influences are mitigated, the models are thrown off.   

[James Gautreau + 86]

[James Gautreau + 86]

Well it's official 2018 decline rates for the first year is 82%. To put that in perspective the 3,800,000 bpd production is now 684,000 bpd. And for production to grow in 2019 they need 3,000,000 bpd just to replace one year of decline, not to mention 2010-2017 production year declines. That is a tall order and personally I don't think they can do it. By my estimates that will be 1,000,000 bpd. That is 4,000,000 bpd just to stay flat, and 2018 was the record brought online in world history 3,800,000 bpd and a growth of 2,000,000 bpd. 

[Gerry Maddoux + 3,627]

Dennis? What do your models say?

I agree with the tall order: that's 2,000 new wells producing an IP of 1,500 each.

Tall order indeed: That's 3,000 wells with an IP of 1,500.

Factor in that the offshore subset is cranking up awfully fast . . . much faster than in the past where there was a five-year lag. In fact, this looks like the after-party for shale, and the pre-party for offshore. 

BUT!!!!!!!!     Dadgum it, look at this in perspective of increasing scarcity. 

There are quite a few shale drilling sites that will produce an EUR of 300,000 barrels. It costs about $5M, these days, to drill one of those. At just $100 oil, that's a payout of . . . $30,000,000. And, like the old days, I think we can reasonably assume that the price of oil will go up linearly at some point--Dennis says about year 2025--and then logarithmically. That's a pretty good investment payout where I come from. 

Compare it to the old conventional wells. I know of tens of thousands of these that were drilled back in the fifties--take the old Hugoton Field, for example (coincidentally, the first field where fracking was used, jazzed gasoline--napalm--mixed with water from the creek). Many of those wells are still chugging along at ten barrels a day: $15,000/month or $180,000/year. 

My point? When oil prices go up to $100, an awful lot of disrespected shale zones are suddenly going to go from trash to treasure. In Divide County North Dakota the whole county is comprised of thin shale that is as oil-soaked as anything out there, yet it has been dissed as only having an EUR of 200-300,000. But it's shallow, so takes less money to get down there. Let's take the low end: 200,000 barrels at $100 per is $20,000,000 payout for a well that cost $3-4M to drill. Eighty-five percent of that comes back the first year, right? Then, as it declines to a paltry 200 blls/d, then 100, and finally a miserly 50, it's still paying out pretty good money, because by the time it gets to 50 blls/d, the price of oil is up to say $150 a barrel and the yearly income from that crappy little well is . . . $2,737,500/year. I'll take a batch of those!

 

 

Edited December 25, 2019 by Gerry Maddoux

[James Gautreau + 86]

	New-well oil production per rig barrels/day				New-well gas production per rig thousand cubic feet/day
Region	December 2019	January 2020	change		December 2019	January 2020	change
Anadarko	606	625	19		4,141	4,230	89
Appalachia	161	164	3		18,662	18,740	78
Bakken	1,515	1,553	38		2,235	2,282	47
Eagle Ford	1,432	1,449	17		4,920	4,929	9
Haynesville	27	27	-		10,322	10,366	44
Niobrara	1,210	1,214	4		4,224	4,229	5
Permian	796	798	2		1,558	1,563	5
Rig-weighted average	821	833	12		4,186	4,092	(94)